The present invention relates to hydraulic fracturing of subterranean formations. More particularly, the present invention relates to controlling the direction of the fracture irrespective of in situ stress orientation.
Many hydrocarbon-bearing formations are characterized by geological features that impart a directional permeability. The most common examples of these types of structures are permeable faults, joints, and micro-cracks. Low permeability formations are candidates for well stimulation. These fracture systems often provide avenues of extremely high conductivity compared to the rock matrix.
The orientation of natural fracture systems such as faults, joints, and micro-cracks is controlled by the in situ stress state at the time the fracture systems were formed. The formations may have occurred tens of thousands to millions of years ago. However, oil field experience in measuring present day in situ stress fields suggest that in most naturally fractured reservoirs, the stress orientation has not changed significantly since the formation of these natural fractures.
The orientation of induced hydraulic fractures is also controlled by the in situ stress state at the time of fracturing. A hydraulic fracture induced from a vertical well typically propagates perpendicular to the minimum horizontal stress. The minimum horizontal stress is also the orientation for most joints, micro-cracks and certain types of faults, specifically normal faults. Consequently, it is very unlikely that a conventional hydraulic fracture treatment will intersect many of the high permeability features of an anisotropic reservoir.
Recent advances in drilling technology have enabled operators to drill horizontal wells of considerable extent in a cross-fracture trend to tap natural fracture systems in formations such as the Austin Chalk with great success. However, in other situations, horizontal drilling alone has not resulted in production success. In formations where there is limited vertical conductivity, very low permeability or natural fractures of limited extent, special hydraulic fracturing techniques can provide an improvement in low production.
One such technique is sequential hydraulic fracturing as disclosed in U.S. Pat. No. 4,687,061 where fracturing fluid is supplied at a first depth in a deviated wellbore to propagate a first vertical fracture as favored by the original in situ stresses of the formation in a direction that is perpendicular to the least principal in situ stress (also known as minimum horizontal stress, .sigma.Hmin). Fracturing fluid is then applied at a second depth within the wellbore while maintaining pressure in the first fracture to propagate a second vertical fracture through the formation in a direction parallel to the least principal in situ stress which should now be favored by the altered in situ stresses due to the first fracture. This second fracture thus intersects the naturally occurring fractures in the formation which are perpendicular to the direction of the least principal in situ stress, thereby linking the naturally occurring fractures to the wellbore to stimulate the production of oil and/or gas from the formation.
Another technique of sequential hydraulic fracturing is disclosed in U.S. Pat. No. 4,724,905 wherein a formation is penetrated by two closely spaced wellbores. A fracturing fluid is supplied to the first wellbore to generate a first hydraulic fracture in a direction perpendicular to the least principal in situ stress. While maintaining pressure in the first hydraulic fracture, a second hydraulic fracture is initiated in the second wellbore. Due to the alteration of the local in situ stresses by the first hydraulic fracture, the second hydraulic fracture is initiated at an angle, possibly perpendicular, to the first hydraulic fracture. Thus, the second hydraulic fracture has the potential of intersecting natural fractures not contacted by the first hydraulic fracture.